Rate Design for the Distibution Edge(1)

RATE DESIGN FOR THE
DISTRIBUTION EDGE
ELECTRICITY PRICING FOR A DISTRIBUTED
RESOURCE FUTURE
PUBLISHED AUGUST 2014
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COPYRIGHT ROCKY MOUNTAIN INSTITUTE

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RATE DESIGN FOR THE DISTRIBUTION EDGE
ELECTRICITY PRICING FOR A DISTRIBUTED RESOURCE FUTURE
AUTHORS & ACKNOWLEDGMENTS
Authors
Devi Glick, Matt Lehrman, and Owen Smith
* Authors listed alphabetically. All authors are from Rocky
Mountain Institute unless otherwise noted.
Editorial Director: Peter Bronski
Art Director: Romy Purshouse
Graphic Designer: Chris Rowe
Graphic Designer: Teressa Luedtke
Contact
For more information, please contact:
Owen Smith (osmith@rmi.org)
Matt Lehrman (mlehrman@rmi.org)
All images courtesy of Shutterstock.
Acknowledgments
The authors thank the following individuals and e-
Lab member
organizations for offering their insights and perspectives on this work:
Dr. Ake Almgren, Orkas, Inc.
George Brown, Duke Energy
Ralph Cavanagh, Natural Resources Defense Council
Emily Felt, Duke Energy
James Fine, Environmental Defense Fund
Jon Fortune, Sunverge Energy
Lena Hansen, Rocky Mountain Institute
Virginia Lacy, Rocky Mountain Institute
Jim Lazar, Regulatory Assistance Project
Eran Mahrer, Solar Electric Power Association
James Mandel, Rocky Mountain Institute
James Newcomb, Rocky Mountain Institute
Curtis Seymour, SunEdison
Ivan Urlaub, North Carolina Sustainable Energy Association
Michael Youth, North Carolina Sustainable Energy Association
Chris Yunker, San Diego Gas & Electric
The authors also thank the following additional individuals and
organizations for offering their insights and perspectives on this work:
Kurt Adelberger, Google
Karlynn Cory, National Renewable Energy Laboratory
Rick Gilliam, The Vote Solar Initiative
Robert Levin, California Public Utilities Commission
Rajan Mutialu, California Public Utilities Commission
Gabe Petlin, California Public Utilities Commission
Paul Phillips, California Public Utilities Commission
Karl R. Rabago, Pace Energy and Climate Center

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TABLE OF CONTENTS
Executive Summary ............................................................................................................................................................................................ 05
01: The Case for Rate Reform .............................................................................................................................................................................. 09
Challenges Posed by Today’s Rate Structures
Navigating Rate Reform
Long-term Issues to Consider
02: Moving Toward More Sophisticated Pricing .............................................................................................................................................. 20
The Attribute Continuum
The Temporal Continuum
The Locational Continuum
03: Recommendations for Regulators ................................................................................................................................................................. 30
Identify Defaults, Alternatives, and Timelines
Manage the Complexity of the Customer Experience
Improve the Rate Design Process
04: Conclusion ...................................................................................................................................................................................................... 35
Appendix ................................................................................................................................................................................................................. 37
Sources .................................................................................................................................................................................................................... 41

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The Electricity Innovation Lab (e-
Lab) brings together thought
leaders and decision makers from across the U.S. electricity
sector to address critical institutional, regulatory, business,
economic, and technical barriers to the economic deployment of
distributed resources. In particular, e-
Lab works to answer three
key questions:
• How can we understand and effectively communicate the
costs and benefits of distributed resources as part of the
electricity system and create greater grid flexibility?
• How can we harmonize regulatory frameworks, pricing
structures, and business models of utilities and distributed
resource developers for greatest benefit to customers and
society as a whole?
• How can we accelerate the pace of economic distributed
resource adoption?
A multi-year “change lab,” e-
Lab regularly convenes its members
to identify, test, and spread practical solutions to the challenges
inherent in these questions. e-
Lab has member meetings, coupled
with ongoing project work, facilitated and supported by Rocky
Mountain Institute.
e-
Lab meetings allow members to share learnings, best practices,
and analysis results; collaborate around key issues or needs; and
conduct deep-dives into research and analysis findings.
For more information about e-
Lab, please visit:
http://www.rmi.org/eLab.
About this paper:
This e-
Lab discussion paper was prepared to support
discussion and dialogue about next-generation retail electricity
pricing approaches appropriate for a future with increasing
quantities of distributed energy resources. It is intended to
stimulate and advance discussion about the advantages and
disadvantages of alternative pricing approaches. The paper
advances a particular point of view, with valuable input from
e-
Lab members and others. It does not, however, reflect a
consensus view of e-
Lab members nor does it reflect policy
recommendations endorsed by e-
Lab members.
e-
Lab is a joint collaboration, convened by RMI, with participation
from stakeholders across the electricity industry. e-
Lab is not a
consensus organization, and the views expressed in this document
are not intended to represent those of any individual e-
Lab member
or supporting organization.
WHAT IS e-
LAB?

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EXECUTIVE SUMMARY
The U.S. electricity system is on the cusp of fundamental change,
driven by rapidly improving cost effectiveness of technologies
that increase customers’ ability to efficiently manage, store,
and generate electricity in homes and buildings. With growing
adoption of these technologies, the electricity system is shifting
toward a future in which the deployment and operation of
distributed energy resources (DERs)1
will have far-reaching
implications for grid operation, investment, and security. Yet,
there is a looming disconnect between the rapidly evolving new
world of distributed energy technologies and the old world of
electricity pricing, where relatively little has changed since the
early 20th
century. By changing electricity pricing to more fully
reflect the benefits and costs of electricity services exchanged
between customers and the grid, utilities and regulators can
unleash new waves of innovation in distributed energy resource
investment that will help to reduce costs while maintaining or
increasing system resilience and reliability.
The stakes are high in getting this transition right. With or without
pricing reform, distributed resources are likely to account for
a growing share of total electricity system investments. DER
developers and customers will optimize their investments and
operations against the price signals provided by the utility,
regardless of whether these prices are aligned to create the
greatest value for society as a whole. The types of pricing
structures most common today for residential and small
commercial customers—bundled, volumetric block rates—
provide little or no incentive for the deployment and operation
of DERs at the times and places where they can create greatest
overall benefit. The perpetuation of these pricing structures in
the face of ongoing improvement in DER cost and performance
and increased adoption of these technologies will result in lost
opportunities for cost reduction and inefficient utilization of
assets on the part of both customers and utilities.
Creating a clean, efficient, and secure 21st
century electricity
system will pivot, in part, on successfully integrating DERs
into the design and operation of the electricity grid—and
pricing provides the incentive structure needed to achieve
this integration. More granular pricing, capable of reflecting
marginal costs and benefits more accurately than today’s
rates do, will provide better incentives to direct distributed
resource investments, regardless of whether investments in and
management of DERs are undertaken by customers, by utilities,
or by third-party service providers. Ultimately, prices could
be adapted to fully reflect a two-way exchange of value and
services between utilities and customers.
1
For more on DERs, see “What Are Distributed Energy Resources?” and Table 2 on page 11.

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EXECUTIVE SUMMARY
NEAR-TERM DEFAULT
OR OPT-IN POSSIBILITIES
LONGER-TERM, MORE
SOPHISTICATED POSSIBILITIES
Time-of-Use Pricing Real-Time Pricing
Energy + Capacity Pricing
(i.e., demand charges)
Attribute-Based Pricing
Distribution “Hot Spot” Credits Distribution Locational Marginal Pricing
Making the transition to new pricing approaches, however, will
undoubtedly pose challenges. In particular, it will require making
trade-offs against one of the hallmark principles of traditional
rate design: simplicity. In addition, introducing new and more
sophisticated pricing structures could have disruptive effects
on existing business models for DER developers. Developing
and implementing new pricing structures will therefore require
effective collaboration among utilities, regulators, technology
developers, and customers. By creating a shared vision of the
future trajectory for prices, however, these parties could create
a pathway whereby DER technology and services can co-evolve
with increasingly advanced price signals.
This report discusses a pathway for deliberately and
incrementally increasing rate sophistication along three
continuums for residential and small commercial (i.e., mass-
market) customers:
1. Attribute unbundling—shifting from fully bundled pricing to
rate structures that break apart energy, capacity, ancillary
services, and other components
2. Temporal granularity—shifting from ﬂat or block rates to
pricing structures that differentiate the time-based value of
electricity generation and consumption
(e.g., peak vs. off-peak, hourly pricing)
3. Locational granularity—shifting from pricing that treats
all customers equally regardless of their location on the
distribution system to pricing that provides geographically
differentiated incentives for DERs
TABLE 1: NEAR- AND LONGER-TERM EVOLUTIONARY RATE STRUCTURES
A transition to more sophisticated pricing is attainable for
large portions of the country, but will require careful planning
and customization to local circumstances. The introduction
of more pricing options for customers—allowing customers
to opt in to new rates that allow them to beneﬁt from actions
that reduce system costs—could allow the implementation of
new approaches in stages, while providing an opportunity for
customers and service providers to experiment with new rates.
For example, pricing options could include a default pricing
option that gradually changes to become more sophisticated
over time, while providing alternative opt-in pricing structures
that are more or less sophisticated than the default for customers
who want or need such choices.
This paper discusses six evolutionary pricing options to consider,
individually or in combination (see Table 1).

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EXECUTIVE SUMMARY
These more sophisticated pricing options need not introduce
unnecessary complexity for customers—third-party aggregators,
energy management software, smart thermostats, and other
technologies can maintain a simple customer experience by
optimizing performance behind the scenes even as greater
differentiation gets built into the rate structures.
Transitioning to some of the new rate structures explored in
this report is possible today or will be realistic in the next few
years in some markets, especially where utilities have already
transitioned to advanced metering infrastructure. In other cases,
implementation of more sophisticated rate structures will take
more time—and possibly even legislative and regulatory reform—
to achieve. Either way, the conversation about how to adapt
electricity pricing to meet the needs of a 21st
century electricity
system has begun. Bringing this transition to fruition will require
participation, dialogue, and collaboration among stakeholders to
deliver successful outcomes.

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01: THE CASE FOR RATE REFORM
The electricity grid is changing. Aging infrastructure requires new
waves of investment to upgrade, while technological innovation—
especially customer-facing distributed energy resources (DERs)—is
transforming the utility-customer relationship. Traditional utility
models, in which investments are recovered through revenue
that assumed consistent or increasing energy sales, are coming
up against rapidly growing DER adoption that reduces utilities’
sales. Further, DERs can shift the traditional load profile of both the
customer and the system as a whole, but they still depend upon
utilization of grid infrastructure to unlock value for customers. In
this new environment, block volumetric pricing (the most common
rate structure for residential and small commercial customers
today) will no longer be able to align stakeholder interests to
deliver maximum value to the system over the long term.
More sophisticated rate structures can unleash new investments
and innovations in DERs, and direct the deployment of these
resources in a manner that maximizes the benefits to the system
as a whole. Further, a failure to evolve to more sophisticated
rates will become increasingly problematic, because as DERs
become ever more accessible and dynamic, consumers will
make or forego investments in DERs (often with long-term
commitments) in more haphazard ways, without sensitivity to
price signals or the impact to the grid as a whole. The transition
to this future of more sophisticated rates will need to be
undertaken with great care. Attention must be paid to ensure
that rates continue to protect affordable access to electricity
and encourage the efficient use of resources while minimizing
unnecessary cross-subsidization between customers and
maintaining a simple customer experience.
MASS-MARKET FOCUS
Rate design varies substantially across customer classes. This paper
primarily focuses on rate reform for residential and small commercial
customers (also referred to here as mass-market customers). As
distributed energy resource adoption grows, elements of rate
structures that are prevalent for large customers can be applied to
the mass market (and can also help to refine and improve the service
options for large customers).

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DEFINITION EXAMPLES
VARIABLE
OUTPUT
CONTROLLABLE
Efficiency
Technologies and behavioral changes
that reduce the quantity of energy
that a customer needs to meet all of
their energy-related demands.
LED Light Bulbs
High-Efficiency Appliances
Building Shell Improvements
Distributed
Generation
Small, self-contained energy sources
located near the ﬁnal point of energy
consumption.
Solar PV
Combined Heat & Power
Small-Scale Wind
Distributed
Flexibility
& Storage
Technologies that allow the overall
system to use energy smarter
and more efficiently by storing it
when supply exceeds demand, and
prioritizing need when demand
exceeds supply.
Demand Response
Electric Vehicles
Thermal Storage
Battery Storage
Distributed
Intelligence
Technologies that combine sensory,
communication, and control functions
to support the electricity system
and magnify the value of DER
system integration (e.g., islandable
microgrids, connected thermostats,
EV chargers, and water heaters).
Microgrids
Home-Area Network &
Smart Devices
Smart Inverter
TABLE 2: DISTRIBUTED ENERGY RESOURCES (DERs)WHAT ARE DISTRIBUTED
ENERGY RESOURCES (DERs)?
DERs are demand- and supply-side
resources that can be deployed
throughout an electric distribution
system to meet the energy and reliability
needs of the customers served by that
system. DERs can be installed on both
the customer side and the utility side
of the meter, and can be owned by the
customer, a third party, or the utility.
DERs can be deployed quickly at small
or large scale and some can provide
rapid response to unplanned changes in
load. The value for each DER varies
by time and location, changing the cost
to serve customers utilizing one or more
of these technologies.
Table 2 (at right) characterizes DERs
based on whether they produce variable
output and are controllable. Here,
controllability is deﬁned by the technical
capability of a resource, regardless of
what entity (e.g., the customer, the grid
operator, or a third party) has the
ability to control it.

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CHALLENGES POSED BY TODAY’S RATE STRUCTURES
Today’s Rate Designs Increasingly Reflect Yesterday’s Grid
Traditional rate design groups customers into broad
classifications (e.g., residential, commercial, industrial), and
establishes rates for these customer groups on the basis of peak
demand, energy use, and customer counts (see Figure 1). The level
of rate design sophistication has varied across these customer
classes. For residential and small commercial customers, for
instance, the majority of their bill is determined through a
per-kWh energy consumption charge (that usually does not
differentiate by time of consumption), along with a small fixed
charge per month. This contrasts with large commercial and
industrial customers, whose bills often are also impacted by their
monthly peak demand (through a demand charge), and whose
energy charge also is more likely to vary by time of use.
This approach has worked well up to now—utilities could make
needed grid investments and recover their costs, and customers
benefited from stable, predictable bills while being incentivized
to conserve energy, if not capacity. But the reality is that for
mass-market customers the behind-the-scenes cost of energy
and all the associated attributes (see Figure 2, page 13) do
significantly vary by time, location, and along other dimensions
not reflected in bundled, volumetric, block pricing. And as DER
adoption grows and changes the manner in which customers rely
on the grid, it will become increasingly important for utilities to
send clear signals and incentives to customers so they know how
to—and are economically motivated to—align DER deployment
with maximizing grid value (for example, reducing peak demand
or shifting use).
LARGE
COMMERCIAL
& INDUSTRIAL
MASS MARKET:
RESIDENTIAL
& SMALL
COMMERCIAL
ENERGY CHARGE CUSTOMER CHARGE DEMAND CHARGE
kWh-based generation costs
(e.g., fuel, wholesale electricity)
Flat, monthly charge covering fixed
costs of servicing customers regardless
of use (e.g., billing, customer service)
Costs of the generation, transmission,
and distribution capacity to serve
peak demand
FIGURE 1: TRADITIONAL COST ALLOCATION
MASS-MARKET CUSTOMER BILLS
GENERALLY DO NOT REFLECT TIME OF
USE, MONTHLY PEAK DEMAND, AND
OTHER FACTORS. MEANWHILE, THE BILLS
OF LARGE COMMERCIAL AND INDUSTRIAL
CUSTOMERS HAVE LONG BEEN
MORE SOPHISTICATED.

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ATTRIBUTE CATEGORIES
Reliable electric service is about more than just electrons. The grid
requires a number of specific attributes to function. Each of these
attributes can be provided by a combination of central and distributed
energy resources. Depending on capabilities, DERs may provide
certain attributes to the grid and require others from it. Some attributes
FIGURE 2: ATTRIBUTES OF RELIABLE ELECTRICITY SERVICE PROVIDED BY DERs
Source: A Review of Solar PV
Benefit and Cost Studies
are more easily quantified and monetized than others. e-
Lab’s earlier
publication, A Review of Solar PV Benefit and Cost Studies,i
identified
these attribute categories (below) and provides a useful framework for
considering which attributes are provided by or required to support the
broader array of DERs.

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DER Adoption is Growing
Currently DERs represent a relatively small but rapidly
growing portion of total demand. For example, through 2013,
approximately 5.5 GW2
of distributed solar photovoltaics (DPV)
produced around 0.1%ii
of total electricity in the U.S. While in
aggregate at the national level this is still very modest, much of
this DPV adoption is concentrated in a handful of markets that
offer a “postcard from the future” for the rest of the nation. In
places where DPV adoption is high, such as Hawaii, rooftop solar
may exceed 100% of minimum load on a circuit on many days.
The rapid growth of solar adoption has also been astounding
by all accounts. From 2009 to 2012, solar of all types grew 82%
per year in the U.S., and is expected to continue growing at 28%
annually during 2014–2016.iii
Other forms of DERs beyond solar
may soon grow nearly as rapidly, further raising the importance of
getting pricing structures right to better direct these investments.
DERs Are Different
DERs have characteristics that are distinct from those of central
generation resources, and consumer- and third-party-owned DERs
make future planning and investment more challenging for utilities
and grid operators, even as DERs open up new opportunities.
• Deployment: DERs are small, modular assets that can be
installed rapidly, strategically (in high-value locations at many
different sizes), and outside of the central resource planning
process. Without proper price signals, utilities have little
inﬂuence as to locations and types of DERs that are installed
on the distribution grid.
• Operation: DERs are installed on the distribution network
and generally operate outside of central dispatching
mechanisms. Some are variable generation resources that
cannot be dispatched on demand—such as rooftop solar
without battery—even though their output can be forecasted
with increasing accuracy.iv
Smart meters, smart inverters,
and two-way control technologies enable DERs to more
seamlessly integrate with central control to help balance load
with resources, or to provide ancillary service requirements.
More sophisticated price signals from the grid to these DERs
can help facilitate the provision of these needed capabilities.
• Ownership: Because many DER investments are made by
customers or third parties outside of normal utility planning
processes, it can be difficult for utilities to predict the long-
term adoption rates of DERs with accuracy. This, in turn,
complicates a utility’s efforts to accurately assess the need
for alternative or complementary investments in central
generation, transmission, or distribution infrastructure.
More sophisticated rate structures can provide customers
and third parties with price signals that can better direct (in
terms of capability, quantity, and location) DER investment
by customers and third parties, and reduce complexity in
assessing long-term adoption trends.2
U.S. Energy Information Administration Form-861S reported 3.6 GW of net-metered rooftop
solar installations through 2012 (http://www.eia.gov/electricity/data/eia861/index.html).
Greentech Media reported 1.9 GW of distributed rooftop solar installed in 2013 (http://www.
greentechmedia.com/ articles/read/Slide-Show-How-to-Really-Disrupt-the-Retail-Energy-
Market-with-Solar)

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12 a.m.
PERCENTOFTOTALCLASSLOAD
TIME OF DAY
4 a.m. 8 a.m. 12 p.m. 4 p.m. 8 p.m. 12 a.m.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
CUSTOMER ON
EV TOU RATE
AVERAGE RESIDENTIAL
CLASS LOAD 2012
CUSTOMER EV
NON TOU
FIGURE 3: AVERAGE RESIDENTIAL VS ELECTRIC VEHICLE CUSTOMER LOADS
Source: Copyright San Diego Gas + Electric. Used with permission.
DERs Don’t Align with Block, Volumetric Rates
As DER adoption grows, customers are becoming increasingly
individualized, depending on whether they have rooftop solar,
on-site storage, an electric vehicle, smart thermostats, or other
technologies. These technologies can provide to or require
from the grid energy, capacity, and ancillary services based on
individual capabilities. But these characteristics vary along many
dimensions that are not reflected in block, volumetric rates.
For example, when a customer is exposed to a high marginal
price tier in an inclining block rate structure,3
rates can both
reinforce and skew the message that price signals should send.
Rooftop PV can look more competitive with retail rates based
on the higher credit received for energy production. Conversely,
electric vehicle charging can be discouraged if the energy used
for charging shifts a customer to a higher-priced use tier.
A move away from block volumetric pricing will allow utilities
to more efficiently direct not just individual DER deployment,
but deployment of DERs in various combinations (such as solar
paired with storage) to deliver a broader and more valuable set
of attributes to the grid.v,vi
In the absence of more sophisticated
rates, customers and businesses are busy deploying thousands
of megawatts of rooftop solar PV without smart inverters, storage
capabilities, or peak-aligned panel orientation, as well as electric
vehicle charging stations that cannot respond to signals from the
grid. More dynamic rates offer significant opportunities to capture
the capacity and ancillary services that are largely lost today,
decreasing grid integration costs and increasing benefits.
WHAT DIRECTION SHOULD MY ROOFTOP SOLAR PV SYSTEM FACE?
Peak energy demand and highest marginal production cost typically
coincide on late summer afternoons. Energy production from
rooftop solar, which has close to zero marginal costs, could therefore
contribute significant value to the system by orienting the panels
towards the west or southwest to best align its affordable peak
production with these periods of high demand when the grid usually
calls upon more expensive generation resources such as peaking
plants. But traditional block volumetric rates do not reflect temporal
cost aspects. As a result, it is most advantageous to customers—most
of whose solar PV is governed by net metering policies that credit
energy consumed from the grid and solar surplus fed into the grid
both at the retail rate—to orient a rooftop PV system towards the
south or even the east (avoiding cloudy afternoons) to maximize total
energy production for the individual customer (instead of to maximize
production aligned with greatest system value, which would be
coincident with customer and system peak).
3
In an inclining block rate price structure, the price per kilowatt-hour increases as specified
usage levels are reached. For example, the first 500 kilowatt-hours are billed at $0.10 per
kilowatt-hour, the second 500 kilowatt-hours are billed at $0.15 per kilowatt-hour, and any
additional kilowatt-hours are billed at $0.20 per kilowatt-hour.

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THE GROWING NEED FOR RAMPING CAPACITY
We live in an age of the California ISO’s famous “duck chart,” which
shows net demand on the grid’s central generation resources in the face
of growing levels of solar PV on the distribution edge. With rooftop solar
depressing daytime net demand on the grid and overall system peak
hitting later in the day after solar production plummets, the duck chart
shows a coming and growing very steep ramp. Resources that can either
smooth such a curve—decreasing both the slope and amplitude of the
ramp—or respond rapidly to meet that curve will thus have immense value.
0
10,000
12,000
3 a.m. 6 a.m. 9 a.m. 3 p.m. 6 p.m. 9 p.m. 12 a.m.12 p.m.12 a.m.
14,000
16,000
18,000
20,000
22,000
24,000
26,000
28,000
HOUR
MEGAWATTLOADFOLLOWINGREQUIREMENT
2012
2013
2014
2015
2016
2017
2018
2020
2019
Ramp Need
~13,000 MW
In Three hours
SAMPLE NET LOAD - MARCH 31, 2012
Today, low-capacity-factorvii
combustion turbines provide this service.
They do so at what some contend is a high cost,viii
and sub-optimally,
considering the emissions and delivery challenges associated with oil or
natural gas.ix
Many contend that customer-sited DERs could be used to
achieve the same goals at a lower price.x
Customers and grid operators
can create more value if rates are designed to encourage behavior
change (e.g., load shifting from peak hours), DER system design (e.g.,
panel orientation), and technology combinations (e.g., DPV + storage) that
mitigate challenges imposed by, in this case, the ramping down of solar in
the late afternoon.
FIGURE 4: THE DUCK CURVE SHOWS STEEP RAMPING NEEDS
Source: CAISO.
Used with permission.

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01: THE CASE FOR RATE REFORM01: THE CASE FOR RATE REFORM
NAVIGATING RATE REFORM
NAVIGATING RATE REFORM
DERs of many types are becoming increasingly widespread and
accessible, yet existing rate structures result in DER investment
that is largely undirected. There is an increasing need to define
the principles to safely integrate and capture the full value of
DERs going forward. When James Bonbright developed his
principles for public utility ratemaking in 1961, they became
the standard that guided the industry for the next half century.
They remain as relevant today as ever, even if we revisit their
interpretation with new eyes that consider the implications
of DERs and a changing grid. Importantly, even though this
paper’s evolved rate structures might feel a revolutionary world
apart from the volumetric block rates that have served the
industry until now, they are still closely aligned with an updated
interpretation of Bonbright’s principles, so they’re not nearly as
radical as one might think at first glance (for more on an updated
application of Bonbright’s principles, see Appendix).
LEVELOFRATESOPHISTICATION
TIME
HIGH
SOPHISTICATION RATE
More highly sophisticated
rates are eventually intro-
duced as an opt-in choice,
but become the default
further out into the future.
TRADITIONAL RATES
Default low-sophistication
rates eventually become an
opt-in choice for customers
who don’t want or need
greater sophistication.
MODERATE
SOPHISTICATION RATE
More-sophisticated rates
are originally opt-in choices
for customers, but eventual-
ly become the default for
most customers. As rates
evolve to even greater
sophistication, moderately
sophisticated rates remain
an opt-in choice.
DEFAULT RATE
OPT-IN ALTERNATIVES
FIGURE 5: DEFAULTS AND ALTERNATIVES
What Will This Future Look Like?
Behind-the-meter DERs are an important component to
building a more resilient and low-carbon electricity system. To
accompany this changing resource mix, the sophistication of the
default rate option used by most customers can be increased,
while still allowing customers the flexibility to opt in to more
or less sophisticated options that meet a variety of customer
requirements (see Figure 5).
REGULATORY COMPACT AND OBLIGATION TO SERVE
Electric utilities are recognized as natural monopolies and are therefore
obligated to serve all customers in their territory. It is important to
recognize that the non-utility owners or operators of DERs (whether
they are individual customers or third-party aggregators) have no
such obligation. Rather, individual customers and third parties elect
to make DER investment choices on the basis of individual project
economics (or other factors). As DER adoption grows, utilities are likely
to face increasing challenges and new costs in their efforts to fulfill this
important obligation. More sophisticated price signals can better align
the DER investment choices that customers and third parties make with
the requirement that the utility provide affordable and reliable service to
all customers within its footprint.

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LONG-TERM ISSUES TO CONSIDER
This framework can enable stakeholders to adequately prepare
for more sophisticated rate offerings, including the introduction
of new technology and service offerings that can maintain a
simplified customer experience even with more sophisticated
rates. Additionally, this structure enables customers to choose
alternatives that are most appropriate for them, whether opting out
of a new default rate option for something more familiar or opting in
to a rate option that is even more advanced.
More granular rates will allow the benefits and costs of each
individual attribute associated with reliable electric service to be
evaluated and clearly and transparently priced. This will enable
regulators to strike an appropriate and intentional balance
between incentivizing DERs and ensuring grid infrastructure
costs are recovered. Valuation of these attributes can be
based on markets or transparent and agreed-upon processes,
producing a system for evolving rates that is more dynamic and
automatically adjustable compared to the current system of multi-
year periods between rate cases.
Customers will respond to these new price signals by shifting
their load profile to take advantage of periods of low-cost grid
service while making more targeted investments in DERs that
can provide greater value to the grid. This combination of price
signals beneficially shifting load (such as through home
pre-cooling, water heater cycling, and strategic electric vehicle
charging) and more optimally directing DER investment can
reduce the need for rarely utilized peaking generation units,
reduce system congestion, and defer distribution upgrades.
To achieve this vision, regulators need to establish processes to
lead stakeholders through the transition from today to tomorrow.
These processes may need to look fundamentally different than
traditional regulatory proceedings, due to the complexity and
pace with which DER deployment is happening. Creative, more
collaborative approaches may be needed to align stakeholder
interests and introduce new rates and accompanying service
offerings in ways that customers will embrace.
The issue of rate design does not exist in a vacuum. For one, the
rate structures proposed in this paper may require investments in
new meters for some utilities.
There are also significant issues around markets, customer
education, the utility business model, and the utility resource
planning process to be addressed in order to create an
environment where more evolved rate designs can be
implemented. Specifically, new market mechanisms are needed
to value and monetize capacity, ancillary services, and certain
environmental attributes in many parts of the country. Customers
need to be educated on the benefits of a shift away from a
100-year-old status quo. Laws and regulations must evolve to
enable utilities and third parties to compete on a level playing
field to provide behind-the-meter products and services to
customers. A previous e-
Lab discussion paper, New Business
Models for the Distribution Edge,xi
explored possible new
business model structures better adapted to a high-penetration
DER future. These issues fall outside of the specific purview of
rate design, but are intimately related to the topic.

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NET ENERGY METERING AND VALUE-OF-SOLAR TARIFFS
According to the Solar Energy Industries Association,xii
by the end
of 2013 more than 445,000 residential and commercial rooftop PV4
customers benefited from net energy metering (NEM) in the United
States, where 43 states have adopted the policy. NEM works by
“spinning the meter backward,” allowing DER customers to consume
generation on site, and paying them for any excess generation in
credits valued at the retail rate under which the customer is served.
When credits from excess generation exceed monthly consumption
from the utility, customers are often able to apply these credits to
future bills (typically at the full retail rate but sometimes at the utility’s
avoided cost). As solar costs have declined and customer adoption has
increased, NEM has become a contentious topic in the industry.
A value-of-solar (VOS) tariff, meanwhile, is a technology-specific
tariff that can be instituted regardless of rate structure that values
specific components of a kilowatt-hour that distributed solar PV (DPV)
produces, such as energy, capacity, grid support services, and some
environmental benefits. This allows utilities to send customers price
signals for the value of DPV based on these unbundled attributes
rather than compensating customers at the retail rate under which they
are served. Multiple viewpoints on the advantages and disadvantages
of VOS tariffs exist, including strongly held and varied viewpoints by
e-
Lab members. VOS is often discussed in the context of a comparison
to net energy metering.
This e-
Lab paper does not take a side on NEM, either for, against, or
advocating reform. Nor does it opine on the relative merits of VOS,
either in isolation or in comparison to NEM. Rather, this paper offers
another set of solutions—moving away from block volumetric pricing
towards more sophisticated structures—that can be implemented
regardless of what happens with NEM and VOS.
4
Not counting other DERs, such as small wind, that qualify for net energy metering.

The Growing Need for Rate
Reform ...................... 09
02
MOVING
TOWARD MORE
SOPHISTICATED
PRICING

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02: MOVING TOWARD MORE
SOPHISTICATED PRICING
Bundled rates are composed of multiple attributes. The values
of some attributes vary by time (across seasons or hours in a
day) as well as by location across a utility’s distribution system;
others remain virtually constant. Depending on the existing
characteristics of a utility’s generation, transmission, and
distribution infrastructure, increasing granularity or sophistication
will provide a different level of value along each individual stream.
We advocate increasing rate sophistication along three
continuums that can be thought of as the what, when, and where
of electricity generation and consumption:
• Attribute Continuum—the unbundling of rates to specifically
price energy, capacity, ancillary services, etc.
• Temporal Continuum—moving from volumetric block
rates towards highly time-differentiated prices that vary in
response to marginal prices or other market signals
• Locational Continuum—delivering price signals that more
accurately compensate for unique, site-specific value
Breaking down rates into these distinct value streams (see Figure
6, page 22) is an important tool to direct investment decisions
that optimize value to all customers as well as to the grid as a
whole. In a highly evolved scenario, we would see increased
rate sophistication along all three axes. For example, customers
could receive real-time price signals across all hours of the day,
with a demand charge that also varies by time, with additional
compensation available to customers who install DERs with the
capability to address distribution hot spots.
Multiple rate options can offer customers choices that meet
their lifestyle, technology requirements, and budget. Within a
handful of years, significant progress could be made to introduce
new, more sophisticated default rate options along all three
of these continuums in many areas of the country, guided by
the particular local circumstances. For instance, the default
rate option could introduce more sophistication along both the
attribute and temporal spectrum, such as two- or three-period
TOU rates for energy coupled with a demand charge. The
demand charge could also vary temporally.
Some customers (perhaps those with no DERs) could elect to
opt out to a less sophisticated fully bundled rate, while other
customers may elect even more sophisticated options that
harness the capabilities of a broader array of DERs. In this case,
a customer who participates in a demand response program
(including automation of multiple appliances) may find the
greatest value in a rate that unbundles time periods to include
peak, off-peak, and critical peak periods with a demand charge.
Meanwhile, a rooftop solar customer with an electric vehicle may
find the most value from a real-time pricing rate that encourages
shifting usage to off-peak periods while compensating excess
generation at a market-based rate.
The transition need not be, and likely would not be, linear across
these continuums, or uniform from one utility service territory
to the next. Each option can provide benefits to customers,
utilities, grid operators, and third parties, but also requires
careful monitoring to ensure that benefits and costs are properly
accounted for and appropriately assigned.

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02: MOVING TOWARD MORE SOPHISTICATED PRICING
FIGURE 6: INCREASING SOPHISTICATION THROUGH RATE STRUCTURE EVOLUTION
ENERGY + CAPACITY PRICING
Breaking apart energy and capacity values begins to unbundle prices,
but leaves many still bundled. Time- and location-based differentiation
is still minimal.
ATTRIBUTE-BASED PRICING
Attributed-based pricing more fully unbundles electricty prices, while
doing so could also add time- and location-based sophistication.
TIME-OF-USE PRICING
Relatively basic time-of-use pricing (e.g., off-peak, peak, critical peak)
begins to add time-based differentation, but could still allow attributes to
remain fully bundled with no location-based differentation.
REAL-TIME PRICING
Real-time pricing, with prices dynamically varying by one-hour or
sub-hour increments, adds much time-based sophistication, but could
still allow attributes to remain fully bundled with no
location-based differentation.
DISTRIBUTION SYSTEM HOT SPOT PRICING
Identifying distribution system "hot spots" begins to add
location-based differentation, but could still allow fully bundled
attributes and little or no time-based differentation.
DISTRIBUTION LOCATIONAL MARGINAL PRICING
Distribution LMP adds location-based sophisitication, and in turn a
high degree of temporal sophistication.
TODAY’S BUNDLED, VOLUMETRIC, BLOCK PRICING
In the simplest system, prevalent today, there is no unbundling
(i.e., fully bundled pricing) with no time- or location-based differentiation.
LOCATIONAL GRANULARITYATTRIBUTE UNBUNDLING TEMPORAL GRANULARITY
LOW HIGH

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THE ATTRIBUTE CONTINUUM
The attribute continuum describes parsing an energy resource
into its specific value components through partial or total
unbundling of electricity rates. The goal is to match services that
a given resource can provide with the needs of the grid to unlock
greater value to the customer and to the grid. The addition of
a capacity (demand) charge is the most common tool available
to begin to unbundle rates along the attribute continuum. As
customers, utilities, and regulators collect and analyze the
growing amount of data available from advanced metering
infrastructure and other sources, rates can move toward fully
unbundled, attribute-based pricing.
Energy + Capacity
An early step in unbundling attributes for mass-market customers
is to separate energy (kWh) and capacity (kW). This approach is
already common for large commercial and industrial customers.
In addition to a fixed customer charge and a per-kWh energy
charge, a demand charge delivers a price signal about a
customer’s instantaneous use. Demand charges can measure
demand in five- or fifteen-minute increments and bill a fixed
dollar per kilowatt rate for the peak monthly use.
Separating energy and capacity charges offers several benefits.
In a world where DERs increasingly threaten the traditional utility
model of investment recovery through volumetric sales, demand
charges can provide utilities with better assurance of investment
recovery while simultaneously providing customers with signals
that motivate them to place less stress and cost on the system.
More specifically, a demand charge more closely allocates cost of
service based on a customer’s load profile. Under this structure,
energy charges are reduced (i.e., closer to wholesale energy
costs) while the fixed costs associated with maintaining adequate
capacity are separately recovered. A demand charge creates an
incentive to add combinations of DERs that more evenly spread
use throughout the day, thereby lowering the impact and cost
on the system. When a customer with a demand charge is also
a net metered customer, the demand charge is not avoided
by excess generation credits, resulting in better cost recovery
for the capacity required to support some DERs.xiii
A demand
charge also begins to reduce intra-class cross-subsidies created
between customers with different load factors.
Demand charges offer several challenges as well. First, some
customers may be unable to spread their use more evenly
throughout the day and could thus be subject to negative bill
impacts from a high demand charge (depending on the price for
the demand charge relative to the unit price of energy). More
advanced meters are also required to measure and bill demand,
and education is also necessary to ensure customers understand
how demand is billed as well as ways to mitigate exposure to
high charges. Despite these obstacles, it is conceivable that
many parts of the country could establish a timeline of just a few
years to introduce demand charges as a default rate option for
mass-market customers, provided appropriate service offerings
and alternative rates were also made available.

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Attribute-Based Pricing
Further along the attribute continuum are subsequent
opportunities to break out and provide price signals for
providing or receiving more and more attributes of electric
service. Attribute-based pricing is technology neutral and could
conceivably incorporate the value of all attributes and services
of energy resources. Instead of “all-in” pricing, the specific
components that comprise a retail electric price per kWh are
separated and priced independent of one another. Under
this structure, credits or charges are assessed for the array of
attributes required for safe, reliable electric service (see
Figure 2, page 13). Unbundling and pricing attributes of electric
service will become increasingly important as DER adoption
grows, because DERs may provide or consume individual grid
attributes, which is a new phenomenon compared to historical
use where consumers simply received all components of reliable
grid service from the utility, and paid for them almost entirely on
a per-kWh basis.
Attributes may vary daily, seasonally, and geographically, as
well as by utility service territory and transmission grid operator
requirements. Stakeholders may also determine that some
attributes, such as job creation, ultimately fall outside of the purview
of rate design and should be compensated via other mechanisms.
In an attribute-based pricing format, rates can be designed to
compensate customers for the specific resources needed and
delivered: energy, capacity, flexibility, reliability, resilience, and
environmental attributes, among others. Asset owners who can
provide these monetized attributes can be compensated for
providing them to the grid on an as needed basis. For example,
a hospital operating a combined heat and power system may
be able to provide excess peak generation to the grid while
continuing to self-supply and use waste heat on site.xiv
Or an
electric vehicle driver can enable the battery to be used as a
demand response resource while charging during the work day.xv
The benefit of attribute pricing is that proper implementation
enables all resources to compete on a level playing field.
Centralized and distributed resources can be compensated for
services provided, and incentivized to install complementary
technologies, such as smart inverters and storage, to enable
the supply of needed grid services. This offers the possibility to
increase penetration of DERs with characteristics that provide
specific services, such as peak management or voltage control
in high-value locations or that can contribute to grid stability at
high-value times of day or season.
Attribute-based pricing also presents challenges to both
customers and to utilities. It is more complicated than traditional,
bundled volumetric pricing (including the possibility that attributes
contributed to the grid may be priced differently than attributes
consumed from the grid). As a result, some customers may be
unwilling to utilize the DERs necessary to capture the full value
of a highly granular rate (and therefore remain on less-granular
rate options). Additionally, markets and methods for valuation
will need to be developed before attribute-based pricing can
be fully deployed. For the foreseeable future, attribute pricing
should be thought of as an option that could be made available to
customers, but not as a default or mandatory rate structure.

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THE TEMPORAL CONTINUUM
SMART HOME RATE
A Smart Home Rate is a hypothetical version of an attribute-based
pricing structure for customers who adopt a combination of technologies
that can respond to sophisticated pricing signals and provide value both
to the customer and to the grid as a whole. Locational and temporal
price volatility more closely reflects the cost of service; customers
pay for consumption and receive compensation based on real-time or
day-ahead price signals. For example, Smart Home Rate customers
with storage technology (stationary or electric vehicle-to-home export
capability) have the ability to fully self-serve from the storage system
(or greatly reduce usage) for short periods of time in response to critical
peak pricing events during the most expensive 100–200 hours per year.
This reduces system demand and protects customers from critical peak
prices. These customers can also respond to low (or negative) wholesale
prices by programming electric vehicles to start or stop charging, pre-
heat or cool the home, and perform other energy-intensive tasks when
prices fall below a pre-defined point. The Smart Home Rate described in
Table 3 (at right) is an example of how customers could be billed when
they employ multiple DERs to meet their electricity needs.
LINE ITEM
BILLING
UNIT
COMPONENTS
Monthly Service Fee $/month
Customer Service
Billing
Metering
Monthly Peak Demand Charge $/kW Capacity
Day-Ahead Hourly Price $/kWh
Energy
Ancillary Services
Real-Time Price $/kWh
Real-Time Signal for Price-
Responsive Loads When Prices
Are Low
Export Credit for Services
Supplied by Customer
$/kWh
Symmetric to Day-Ahead Hourly
$/kWh
A Smart Home Rate that clearly delivers the price for values sought from different resources
can encourage investment in resources that provide value to both the customer and the grid.
Consumption and supply prices are assumed to be symmetrical but could vary by attribute.
TABLE 3: SMART HOME RATE
The second value stream comes from services needed by the
grid (and the attributes that an energy resource can provide) on
a temporal basis. The cost of generating electricity varies over
the course of a day’s load profile, as utilities call upon more
expensive generation resources to meet peak demand. Thus
DERs that can shave that peak and smooth the day’s load curve,
including distributed generation coincident with peak that can
provide an economical alternative to expensive peaking plants,
can provide value—if provided the right price signals.
Time-of-Use Pricing and Critical Peak Pricing, explained in
subsequent sections, both send price signals to shift use to off-
peak periods of day. Real-Time Pricing represents the highest level
of granularity on the temporal spectrum.

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Time-of-Use Pricing (with Critical Peak)
Time-of-use (TOU) pricing represents a move towards more
granular pricing on the temporal spectrum. It is becoming
increasingly common today, and is used to communicate
information to customers on how the value of energy services
provided by—and to—the grid vary by time. Under this rate
design, customers are billed different rates across peak, shoulder
peak, and off-peak periods. To capture additional value, the
addition of a critical peak period (CPP), which occurs only during
grid emergencies or during the most expensive hours of the year,
sends a temporally-specific price signal to customers about the
high cost of energy in an effort to shift and/or reduce use.
The benefit is that customer interaction with the grid is priced to
more closely match the cost to generate, transmit, and distribute
energy. Customers will know when the most and least expensive
times of day are to use energy, how to align DER installations to
meet peak demand, or where it is economically advantageous
to add storage (which may be in locations that not only provide
value to the customer but also to the grid as a whole) based
upon the availability and accessibility of enabling technologies
and the implementation of robust education and marketing
efforts. When enough customers reduce their peak demand, or
install DERs to provide peak energy to the grid, the utility’s peak
demand can either decrease or shift. This is significant because
peak demand on a system level is one of the main factors that
drive the need to build central generation assets, especially
“surplus” generators built to meet peak spikes but which
otherwise sit idle much of the time when demand doesn’t call for
them. Further, as DER penetration increases, load requirements
can also shift. The California “duck curve” scenario (see Figure
4, page 16) creates a need for flexibility resources, whether from
load shifting, DERs, or central energy resources.
On the flip side, the primary challenges facing TOU rates relate
to customer acceptance and program design. While TOU is
common in many parts of the country, it is primarily offered
as an optional rate and often with only one choice of time
periods. Broadly defined time periods may make it too difficult
for customers to shift use (e.g., on-peak pricing periods may
commonly be seven hours in duration). Likewise, if the incentive
to reduce use is not large enough, then it may not be worth the
effort to change behavior. Despite these challenges, successful
TOU programs to datexvi,xvii
suggest that it is plausible that many
areas of the country could move to TOU pricing as a default
rate option within a matter of a few years, provided appropriate
service offerings, customer education, and alternative rates were
also made available.

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-10
0
10
20
4 a.m. 8 a.m. 4 p.m. 8 p.m. 12 a.m.12 p.m.
30
40
50
60
70
80
90
100
RATE($/MWh)
TIME OF DAY
FLAT VOLUMETRIC RETAIL TYPICAL TOU PRICINGHOURLY PRICING
FIGURE 7: TEMPORAL PRICING STRUCTURE
Although a TOU rate more equitably charges customers for usage at different times of the day, it
does not capture short-term price spikes that can significantly raise prices during an otherwise
low-price time period. In the chart above, a TOU customer is exposed to peak, shoulder peak
and off-peak prices each day. The peak and shoulder peak prices are in effect for almost twelve
hours each day, even though the actual peak market price is different each day (and occurs
over a much shorter time period). This creates a scenario in which customer behavior must be
responsive over a long period of time when an hourly price signal could encourage investment in
DERs that could help to reduce the price spikes, benefitting all customers.
Real-Time Pricing
Real-time pricing is the most granular structure on the temporal
continuum. It uses hourly day-ahead or sub-hourly (e.g., five-
minute interval) spot market prices to bill and compensate
customers for services required and provided.
A key benefit of this degree of sophistication along the temporal
continuum is that it can unleash innovation in DERs and direct
investment in new technologies that can provide great benefits
to the system more cost effectively and with less potential for
cross-subsidization than less-sophisticated rate options. For
instance, under hourly pricing, a customer (and in turn the system
as a whole) may benefit from installing a combination of solar
PV and battery technology that might not be economical under
a less-granular rate structure such as traditional TOU rates. The
battery system in this case could be sized to power the home
for short periods, like the one or two hours of the day when
energy prices are expected to be highest. These granular time
periods offer the added benefit of shortening the window during
which the battery system is needed (thus enabling a smaller and
more affordable battery). By comparison, the rate differentials
between on- and off-peak periods under a two-period TOU rate
are not as great as they would often be under hourly prices, and
the time periods for the on-peak period may be too long to be
economically attractive for customers to consider.
Despite its merits, not all utilities or grid operators are yet capable
of deploying widespread real-time or hourly pricing. Additionally,
many customers may not be willing to adopt rate structures
this sophisticated for the foreseeable future. That said, there
are significant opportunities to make real-time pricing easy for
customers by pairing it with technologies that can automatically
adjust use in response to granular price signals. In the near term,
it is plausible that many areas of the country could make hourly
or real-time pricing available as an option for customers, enabling
solution providers to combine technologies and services to
deliver value to customers and to the system as a whole.

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THE LOCATIONAL CONTINUUM
system upgrades (similar to non-transmission alternativesxviii
).
This is a step that offers an alternative to significant distribution
investments, such as new substations. Substation upgrades are
not only expensive but can require decades for full cost recovery
(subject to threats from continued evolution of DER technology).
Another benefit is the ability to specifically target locations with
short-term availability of incentives for DER installation. By doing
so, utilities can control the costs of incentive programs while
maximizing return on investment. For example, the Con Edison
Brooklyn/Queens Demand Managementxix
plan seeks DERs—
ranging from on-site generation to storage to load management
technologies—that collectively can defer the need for a $1 billion
substation upgrade. The program is only available to customers
within the area served by the existing substation. If successful, it
could be expanded to other areas as needs are identified.
Unfortunately, hot spot credit or pricing can be challenging since
the ability of DERs to defer or obviate distribution investments
is a point of debate, and also because distribution system
upgrade plans are not commonly available to all stakeholders
until the decision to invest by the utility has already been made.
Regulators can add significant value by enabling and/or requiring
utilities to share data on system operations (while addressing
data privacy concerns) that can provide a broader group of
stakeholders with the ability to offer non-distribution alternatives
to the system planning process.
The third value continuum involves more granular pricing on
a locational basis. In order to capture this value, utilities and
grid operators can offer credits or price signals over a short- or
long-term horizon, based on specific system needs. Distribution
System Hot Spot rates or incentives can begin to move rate
design in a more location-based responsive direction, while
Distribution Locational Marginal Pricing (Distribution LMP)
represents the highest level of granularity in this stream.
Distribution System Hot Spot Pricing
“Hot spots” are locations on the distribution system that suffer
from congestion due to overloading of infrastructure. When
new load is added, particularly during peak periods, it can be
more cost effective to signal customers to install DERs—ranging
from demand response to storage to distributed generation
that can shift or reduce load—to alleviate stress. Customers
that install DERs in high-value locations or with high-value
temporal attributes could be compensated for their contribution
to the system through incentives such as credits. One method
to calculate the value is to compare the savings produced by
the DER relative to the cost of deferred or avoided distribution

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Distribution Locational Marginal Pricing
The Distribution Locational Marginal Pricing (Distribution LMP)
concept is a distribution system version of the transmission
system locational marginal price common today in many
wholesale markets. Instead of sending short-term price signals in
the form of a credit under a “hot spot” design, a distribution LMP
simply provides hourly or sub-hourly price signals at nodes on the
distribution system. In one iteration, customers could be billed,
and compensated, based on the services required and provided
at each node. Customers would receive more accurate price
signals on which to base their DER investment decisions and grid
operations would be less likely to be disrupted by DERs in low-
value locations. Another variation would be to calculate the value
of line losses and cost of potential line failures at various load
levels and bill customers for services required or provided.xx
A distribution LMP is more advanced than the “hot spot” credit
program in its focus on real-time system conditions. Rather than
focus on long-term system planning by providing credits only in key
locations, a distribution LMP charges and compensates customers
for value consumed and provided at any point on the distribution
system with prices that reﬂect daily or hourly system events.
There are several challenges that may limit the possibilities of
distribution LMP. One very important challenge is that it could
simply be untenable from a public perception standpoint to
charge customers materially different rates based on where they
live. This may be considered counter to long-standing notions of
providing universal access to affordable electric service. Another
challenge is that many utilities and grid operators lack the ability
to provide pricing on such a granular level on the distribution
system. Signiﬁcant metering and communications infrastructure
may be required to capture and convey accurate price signals.
Additionally, customers in areas with high distribution LMPs may
not be able to respond to sophisticated price signals.
In short, this level of locational sophistication is not likely to be
practical, at least for the foreseeable future. In the meantime, the
value of establishing structures to address the most high-value
“hot spots” on the system could be further explored and pursued
in many areas of the country within the coming years.

03
RECOMMENDATIONS
FOR REGULATORS

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03: RECOMMENDATIONS FOR REGULATORS
Increasing DER adoption presents a need for rates to evolve
along the locational, temporal, and attribute spectrums. However,
customers, utilities, grid operators, and solution providers may
not yet be ready to jump to highly granular attribute pricing
today. A multi-stage transition with defaults and alternatives
can gradually increase rate sophistication while still allowing
customers to opt in to more or less sophisticated rates.
Regulators can enable utilities and third-party service providers
to provide new technologies and solutions to keep the customer
experience simple while introducing more sophisticated price
signals. And as rates become more sophisticated, regulators can
focus on increasing the accuracy and transparency of the rate
design process to maximize the value available to the system.
IDENTIFY DEFAULTS, ALTERNATIVES, AND TIMELINES
Today, the default rate is relatively simple, and is generally the
simplest option available to customers. Regulators can establish
processes to identify new, more sophisticated rate options (such
as TOU rates with demand charges) that could become the default
within a period of a few years. In advance of this option becoming
the default, customers could be given the opportunity to opt in to
it or other even more sophisticated options. After it becomes the
default, customers could have the option to opt out of the default
to either a simpler rate (perhaps similar to what they’ve had before)
or into even more sophisticated options. Over time, the default
option could increase in sophistication yet again, following the
same pattern.
Multiple, highly granular rate options can co-exist as choices—
hourly pricing, TOU block pricing, critical peak pricing, inclining
block rates, and others—as long as customers, or the service
providers serving them, can easily identify the value associated
with each relative to their lifestyle and technology choices.
As an alternative to the traditional model of pilots that are common
today, utilities can offer customers and solution providers a staged
approach to implementing more granular rates (see Figure 5, page
17). This will allow utilities, customers, and solution providers time
to analyze customer response, to identify any required supporting
technologies, and to address concerns from other stakeholders so
that the transition is as smooth as possible.
DEFAULT TIME-OF-USE RATES IN CALIFORNIA
The California Public Utility Commission, at the direction of Assembly Bill
327,xxi
is undergoing a process of rate reform. AB 327 lifts many of the
restrictions on residential rate design. The state’s investor-owned utilities
(IOUs) can now propose residential rates more reﬂective of cost, in
keeping with the Commission’s principle that rates should be based on
cost-causation and other rate design principles.xxii
AB 327 also contains
limits designed to protect certain classes of vulnerable customers and
permits default TOU pricing for residential customers starting in 2018.
Thus far, SDG&E is the only one of the three California IOUs to propose
transitioning all residential customers to default TOU rates starting in
2018, although all three have proposed collapsing the current four-tier
inclining block rate structure to a two-tier structure. If default TOU is
adopted in 2018, a customer must have the ability to opt out to a non-
TOU rate with at least two tiers. Customers will have access to a rate
calculator to compare options and also have one year of bill protection
to ensure the annual bill on the new TOU rate does not exceed the
amount the customer would have paid on the non-TOU rate.
This multi-year, multi-step transition gives customers and solution
providers ample time to understand the requirements and test new
service options. Most importantly, evidence suggests the majority of
customers will remain on the default option, even if the default option
contains time-differentiated pricing, if the default is designed and
implemented well.xxiii

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MANAGE THE COMPLEXITY OF THE
CUSTOMER EXPERIENCE
MANAGE THE COMPLEXITY OF THE CUSTOMER EXPERIENCE
To accompany the default and alternatives framework outlined,
utilities or third-party service providers need to find ways to
manage the complexity of the customer experience (see Figure 8).
The typical residential customer wants to save money without
sacrificing time or convenience (or at the very least, not more
than the value of the savings).
COMPLEXITY OF CUSTOMER EXPERIENCE
RATESOPHISTICATION
LO
W
HIGH
HIGH
Sophisticated Rates With
Technologies & Solution
Providers Simplifying The
Customer Experience
Customers Respond To
Price Signals Directly
(e.g., Respond To TOU Rates
Through Behavior Change)
DESIRED STATE FOR
MOST MASS-MARKET
CUSTOMERS:
CURRENT & FUTURE
STATE FOR SELECT
CUSTOMERS:
Simplified Rates With No
Role For Complexity
Management
TRADITIONAL
EXPERIENCE FOR MOST
MASS-MARKET
CUSTOMERS TODAY:
FIGURE 8: MANAGING RATE COMPLEXITY FOR THE CUSTOMER
Highly simplified rate structures leave value on the table by
offering few opportunities to take action that can achieve
significant savings. More granular rates that more fully
differentiate the value to serve a customer will drive utilities
and third-party solution providers to develop technologies and
services that increase savings and decrease complexity. The
service providers can earn revenue through the service they
offer, the customer can gain value through a lower monthly bill,
and the utility and grid can lower costs through a more efficiently
operated system. It is important to consider that regulatory reform
outside of rate design (such as data sharing and privacy standards
and the ability of utilities to sell and own behind-the-meter
products and services) may be required to promote competition
that can help maintain a simple customer experience.
Bridging rate sophistication for customers – Utilities and third-party solution providers can serve
as intermediaries to evaluate more sophisticated rate designs for customers, offering products
and services to capture bill savings while maintaining a simple customer experience.
SOPHISTICATED RATE STRUCTURES CAN
UNLEASH INNOVATIVE TECHNOLOGIES
AND SERVICES THAT CAN PROVIDE
SIGNIFICANT SAVINGS TO CONSUMERS
AND UTILITIES WHILE MAINTAINING A
SIMPLE CUSTOMER EXPERIENCE.

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IMPROVE THE RATE DESIGN PROCESS
To support more sophisticated rates, regulators need to enable
improvements to the rate design process itself. Specifically,
regulators should:
• Increase the quantity and quality of electricity system
data available to all stakeholders while addressing data
privacy concerns
• Enhance transparency of valuation methodologies
• Determine how non-monetized attributes should be included
in (or excluded from) rate design
Increase the Quantity and Quality of Electricity System
Data Available to all Stakeholders While Addressing
Data Privacy Concerns
The effectiveness of resource deployment decisions will improve
if regulators can increase both data transparency and availability
for all stakeholders. The reach of data collection infrastructure
such as advanced metering infrastructure (AMI) on the utility
side of the meter and cloud-connected solar inverters, electric
vehicle charging stations, and home automation systems on the
customer side of the meter is currently limited. Regulators are
in the challenging position of trying to evaluate the benefits of
new technology in the absence of many years of operational
data. But new analysis and modeling capabilities can combine
what does exist from smart meters, rooftop installations,
and charging stations to predict system requirements. More
importantly, solution providers and customers can participate. By
employing newly available dataxxiv
from these sources, they can
leverage more granular prices to interact with connected devices
throughout the home.
Through this process, care should be taken to ensure that
data privacy concerns are well addressed. Options to alleviate
concerns include enabling streamlined customer consent or
adequately masking or aggregating specific data.
Enhance Transparency of Valuation Methodologies
Nationwide consensus on specific attribute valuation
methodologies is unlikely (and perhaps undesirable, given
differences across utilities and geographies). What regulators
should strive for is agreement on principles of valuation. e-
Lab’s
earlier report A Review of Solar PV Benefit and Cost Studiesxxv
revealed a collection of best practices that together can produce
a rigorous methodology to value DERs. These include:
• A transparent and open process for identifying and
evaluating attributes
• An agreed-upon procedure to continually update the
methodology
• Proper oversight to ensure equity for all stakeholders
• Simplicity to enable participation by all interested
stakeholders, regardless of size or funding
In Minnesota, the process to establish a value-of-solar (VOS)
methodology included an open review of potential attributes,
followed by adoption of a transparent valuation methodology
to set thefinal rate. Stakeholders had the ability to contribute at
every stage of the process. Although not all interveners agreed
on the final value, the approach allowed for important stakeholder
interactions and rigorous debate that will inform future refinement.

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Determine How Non-Monetized Attributes Should Be Included
In (or Excluded From) Rate Design
Services that are relatively straightforward to measure and
represent costs directly incurred by the utility, such as energy,
are commonly included in rates. Others, such as ancillary
services and environmental benefits that are harder to measure,
or security and economic development which are not yet
generally monetized, are not broken out in rates.
However, just because an attribute may be difficult to quantify, its
value is not automatically zero.xxvi
The same applies to attributes
that are not presently monetized in rates and regulators may
ultimately conclude that some attributes are best addressed
outside of rates, but this is difficult to determine prior to a
comprehensive analysis.
Regulators have multiple options when an attribute has a benefit
or cost associated with it (such as carbon emissions), but it is not
clear how to accurately calculate that value. In Minnesota the VOS
calculation used the Environmental Protection Agency-developed
“Social Cost of Carbon”xxvii
as a proxy to assign value for the
reduction in carbon emissions from solar generation. Similarly,
the Bureau of Land Management offers a model for calculating
the environmental mitigation expense for federal lands based
on acquisition, restoration, and preservation costs.xxviii
The
National Renewable Energy Laboratory’s Jobs and Economic
Development Impact models estimate the economic impacts
of constructing and operating power plants, fuel production
facilities, and other projectsxxix
and many utilities calculate the
benefits of attracting and retaining new sources of load to offer
economic development rate reductions.

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04: CONCLUSION
Historically, simplified rate structures for residential and small
commercial electricity customers—embodied in bundled,
volumetric, block rates—were both appropriate and necessary.
For one, customers could reasonably be lumped into a relatively
small number of large, averaged rate classes with similar load
profiles and relationships with the grid. For another, the system
lacked the tools on both sides of the meter—especially advanced
metering, data, and communications infrastructure—to enable
more sophisticated approaches.
But deployment of new grid technologies and proliferation of
myriad distributed energy resources—including rooftop solar,
smart thermostats, electric vehicles, demand response, battery
storage, and much more—are fundamentally changing the
grid. That changing grid requires new rate structures for the
distribution edge, better aligned with the evolving 21st
century
electric grid. In addition, DERs will continue to garner growing
levels of investment, which will only further the expanding
disconnect between 20th
century rate structures and a
21st
century grid.
More sophisticated rate structures can provide better price
signals that will enable central and distributed energy resources—
and utilities, customers, and third-party solution providers—to
compete on a fair and level playing field and to share in value that
can more optimally direct investment in support of an affordable,
reliable, low-carbon grid.
This paper advocates deliberately and incrementally increasing
rate sophistication along three continuums: attribute, temporal,
and locational. It describes six hypothetical rate structures
that could so move the needle—separately, in parallel, or in
combination—by partially or wholly unbundling the attributes
implicit in block electricity prices; honoring the way the cost of
electricity generation and consumption varies over the course of
hours, days, and seasons; and recognizing the differential cost to
serve customers at different locations throughout the
distribution network.
A transition to more sophisticated and highly differentiated
pricing should happen as an evolution that allows all stakeholders
to become comfortable with increasing sophistication. That
evolution includes an incrementally more sophisticated default
option implemented over time, while allowing additional rate
options with greater and lesser sophistication for customers that
want or need it. The evolution should also include—via third-party
solutions providers, energy management software, “intelligent”
systems, and other such customer “interfaces”—that preserve
behind-the-scenes granularity while allowing for a simpler, more
user-friendly customer experience.
Several of the rate structures we propose are possible now
or within the next few years in many utility service territories,
especially those where advanced metering infrastructure is
already in place. Others might require longer time frames and
legislative and regulatory reform to become realistic options. Thus
we conclude with recommendations for regulators on how to
support an evolution toward more sophisticated rate structures.
In an era when the distribution edge is the front line of the
electric grid’s evolution, we need rate structures that reflect its
new landscape. Hopefully, this discussion paper helps take the
industry a step in that direction.

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APPENDIX
PRINCIPLES TO GUIDE RATE DESIGN IN A HIGH-DER FUTURE
In 1961, James Bonbright laid out a set of principles to guide the
design of public utility rates.xxx
These principles, which promoted
rate simplicity, stability of the customer experience, utility
revenue recovery, fair distribution of cost among customers, and
efficiency of energy use became the foundation of public utility
ratemaking in the U.S. for the next half century.
Today, however, rates must address dynamic customer
behavior, increasingly cost-effective energy efficiency options,
and competitive on-site generation, storage, and automation
technologies that reduce overall system peaks and can shift
distribution feeder peaks to earlier or later in the day. Bonbright’s
principles remain relevant and appropriate in large measure even
today, although modern-day challenges and opportunities require
certain facets of these classic principles to be reinterpreted. In
Table 4 (at right) are the original Bonbright principles along with a
suggestion of how they should be interpreted given the future we
are facing and capabilities that were previously not available.
WHAT TO PRESERVE FROM TRADITIONAL RATE DESIGN
The benefits offered by more granular rate design should not
overshadow the components of rate design today that offer
value to individual customers and the grid as a whole. Social
equity, resource efficiency, a simple customer experience, and
the minimization of unintended cross-subsidies are important
features that can be preserved—and improved upon—as rates
evolve to meet the needs of customers and DERs.
BONBRIGHT PRINCIPLES 21ST
CENTURY INTERPRETATION
Rates should be practical: simple,
understandable, acceptable to the
public, feasible to apply… and free from
controversy in their interpretation.
The customer experience should be
practical, simple, and understandable.
New technologies and service offerings
that were not available previously can
enable a simple customer experience
even if underlying rate structures
become significantly more sophisticated.
Rates should keep the utility viable,
effectively yielding the total revenue
requirement and resulting in relatively
stable cash flow and revenues from year
to year.
Rates should keep the utility viable
by encouraging economically efficient
investment in both centralized and
distributed energy resources.
Rates should be relatively stable such
that customers experience only minimal
unexpected changes that are
seriously adverse.
Customer bills should be relatively stable
even if the underlying rates include
dynamic and sophisticated price signals.
New technologies and service offerings
can manage the risk of high customer
bills by enabling loads to respond
dynamically to price signals.
Rates should fairly apportion the utility’s
cost of service among consumers and
should not unduly discriminate against
any customer or group of customers
Rate design should be informed by a
more complete understanding of the
impacts (both positive and negative)
of DERs on the cost of service. This
will allow rates to become more
sophisticated while avoiding
undue discrimination.
Rates should promote economic
efficiency in the use of energy as well as
competing products and services while
ensuring the level of reliability desired by
customers.
Price signals should be differentiated
enough to encourage investment in
assets that optimize economic efficiency,
improve grid resilience and flexibility and
reduce environmental impacts in a
technology neutral manner.
TABLE 4: A 21ST
CENTURY INTERPRETATION OF THE BONBRIGHT PRINCIPLES OF
PUBLIC UTILITY RATEMAKING

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APPENDIX
Continued Focus on Social Equity
Consideration of any new rate design must be undertaken
with assurances that customers will have access to adequate,
affordable electric service. Some customers will be unwilling or
unable to take advantage of more dynamic rate options. This
may result in adverse rate impacts and an inability to pay the
monthly bill if proper protections are not in place. One solution
is to offer multiple rate options, which will allow less flexible
customers to choose the rate that serves them best. Another
solution is to offer across the board percentage discounts for low
income customers, which would allow these customers to still
receive the same price signals as other customers, but simply
pay a lower bill.
Continued Focus on Resource Efficiency
Care should be taken to preserve appropriate emphasis on
resource efficiency and conservation as rate design evolves. For
instance, if increasing portions of customer bills are collected
in the form of fixed monthly charges—and less in the form of
volumetric charges or other types of charges that the customer
has the ability to influence—the incentive to conserve could be
diminished. New rate designs can maintain the focus on resource
efficiency by limiting the portion of a customer bill collected
through fixed charges, or layering in tiered-volumetric rates with
time-differentiated rates to simultaneously promote resource
efficiency and peak-time load shifting.
Simple Customer Experience
A shift to more granular and dynamic rates will need to be
undertaken in tandem with efforts to introduce new products
and services that can automate customer responses to price
signals to maintain a simple customer experience. Smart
grid technologies are being rapidly deployed and there are
increasing opportunities for solution providers (including third-
party aggregators, utilities, and others) to manage complexity
on behalf of the customer, so that the customer experience is at
least as simple or more so than it is today. For example, home
energy management systems can respond to price signals from
the utility and alert customers to critical peak pricing periods.
BONBRIGHT’S PRINCIPLES REMAIN
RELEVANT AND APPROPRIATE TODAY,
ALTHOUGH GROWING ADOPTION OF
DISTRIBUTED ENERGY RESOURCES
REQUIRES A FRESH INTERPRETATION.

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APPENDIX
Minimal Unintentional Cross-Subsidization
Cross-subsidies5
have always been present in rates. The
important thing is to ensure that any subsidies within and across
customer classes achieve the policy goals they were designed to
achieve without creating undue burden on individuals or groups
of customers. It is also essential that legislators, regulators and
other stakeholders fully understand how cross-subsidies in rates
change as the penetration of DERs increases.
Cross-subsidies that are exacerbated as DER penetration grows
can be managed through more granular rate design. Electric
vehicle customers, for example, can be both subsidized by or
subsidize other customers under traditional rate design. Inclining
block rates penalize customers as use increases, even if the
increased use is the result of EV charging during off-peak hours.
Conversely, electric vehicle charging during peak periods can
be subsidized under a bundled, volumetric pricing structure. The
proposed Vehicle Grid Integration Pilot Program at San Diego
Gas & Electricxxxi
is designed in part to alleviate these subsidies.
Price signals encourage charging at times most valuable to both
the customer and the grid. Proposed rates are based on hourly
day-ahead pricing and include price reductions for customers
who can charge during surplus energy events, when spot market
prices are negative.
5
Cross-subsidies in electric rates occur when the cost to serve a customer or class of customers
is not fully recovered in the rates charged to the customer, with the difference made up through
increased rates on other customers or customer classes. This can be the result of intentional
policy implementation (e.g., discounts for low income customers) or can occur naturally over time
(e.g., when a group of customers reduces consumption to the point that loss of kilowatt-hour
sales causes rates to be increased to account for the loss in revenue.

4141
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ENDNOTES

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